Steam injection techniques, such as steam stimulation and steam flooding, have been used to recover immobile heavy oils and to enhance the oil recovery from older wells where the natural field pressures are too low for unassisted production. They are designed to reduce the reservoir flow resistance by reducing the viscosity of the crude.
These techniques involve injection into the well of a high temperature wet steam in cycles of thousands of cubic meters at a time. Wet steam is a mixture of steam and varying amount of hot liquid water, the quality of wet steam generally ranging from 35% to 80%. Because of the density difference between the two phases of the wet steam, the vapor phase preferentially enters the upper part of the injection interval and the liquid phase preferentially enters the lower part.
When groundwater, river water, or lake water is used as feedwater to generate wet steam, the liquid phase of wet steam is generally basic (having a pH in excess of 11) and the vapor phase of the wet steam, when condensed, is acidic (having a pH of about 4.0 to 4.5). This partitioning is due to the bicarbonate contained in the source water decomposing to CO.sub.2 and OH.sup.-, as shown in Equation 1 below: ##STR1## The CO.sub.2 is volatile and enters the vapor phase, which produces a low pH in the liquids condensed from the vapor phase. The OH.sup.- ion stays in the liquid phase and causes a high pH in the liquid phase.
Associated with using these wet steams in steam injection is the problem of silica dissolution. Coupled with high fluid temperatures, both the liquid phase and the liquids from the condensed vapor phase are capable of rapidly dissolving reservoir rocks, such as sandstone, carbonate, diatomite, porcellanite and the like. For pH valves above 11.0 and temperatures above 177.degree. C., the silica and silicate dissolution rates are orders of magnitude higher than at neutral/ambient conditions. Also, because the reactions for dissolving siliceous reservoir rocks are base consumers, the liquid pH decreases rapidly as the fluid moves away from the wellbore, causing the dissolution reactions and solubility to diminish rapidly and causing the reaction products (such as aluminosilicates and other metal silicates) to precipitate downsteam in the pores. This precipitation decreases the formation permeability and decreases well injectivity.
This problem of silica dissolution was addressed in U.S. Pat. No. 4,475,595; U.S. Pat. No. 4,572,296; and U.S. Pat. No. 4,580,633. All three of those patents are incorporated herein by reference for all purposes. U.S. Pat. No. 4,475,595 discloses adding an ammonium inhibitor to the feedwater or to the wet steam. U.S. Pat. No. 4,572,296 discloses adding an ammonium inhibitor and a compound which hydrolyzes in steam, providing a buffering effect in the liquid phase to prevent excessive pH reduction. U.S. Pat. No. 4,580,633 discloses adding an ammonium inhibitor and an organosilicon compound. In each case, the amount of added ammonium inhibitor is determined by the bicarbonate concentration of the steam.
Also associated with using these wet steams is the problem of permeability damage of hydrocarbon formations containing clay. Clay is a general term for minerals such as kaolinite, illite, chlorite, smectite, and mixtures thereof. Most of these minerals have a very distinctive, book-like structure made of pages of thin layers of hydrous aluminosilicates. During steam injection, the reaction of fresh water and some clay minerals behaves much like a soaking wet book: they swell, ripple, and break off. Some clay minerals swell to 600% to 1000% of their initial volume when subjected to fresh water during steam injection. This results in (1) reducing pore volume for fluid flow and (2) plugging pore channels from fines migration. The swelling of clay and the migration of clay fines severely inhibit steam injectivity into the formation. Formations that contain clay minerals are susceptible to fresh water injection that cause the clay to disperse and migrate. When fines move downstream, they tend to bridge in pore constrictions to form miniature filter-cakes throughout the pore network. This can decrease steam injectivity in the lower interval where liquid water is injected and also in the upper injection interval where vapor phase condensation takes place. In some cases, clay structural expansion may contribute to this decrease in permeability.
It is well known that clay minerals expand greatly when the interlayers are occupied by sodium ions. A sodium ion can absorb twelve or more irregularly oriented water molecules. If the interlayer sodium ions are replaced with ammonium ions, the swelling problem may be substantially reduced.
As previously discussed, ammonium salts have been used to control the pH of wet steam and decrease silica dissolution. But for a high-clay-content reservoir, the concentration of ammonium ions sufficient to remedy the silica dissolution problem is usually inadequate to reduce permeability damage produced by clay minerals.
u.S. Pat. No. 4,549,609 by Watkins et al, filed Aug. 15, 1984, which is hereby incorporated by reference, attempts to solve this problem. It teaches injecting an ammoniacal nitrogen-containing compound into the wet steam to reduce permeability damage. But this patent fails to address another problem associated with ammonia salt treatment.
To treat a high-clay reservoir, large amounts of ammonium salts must be added to the steam. Generally, this reduces the pH of the residual liquid phase of the wet steam to the 2.0-4.0 range. This acid overtreatment corrodes the steam generation and steam transportation system.
Accordingly, the need exists for a further improved steam injection treatment which simultaneously (1) prevents permeability damage to a hydrocarbon-containing formation which contains clay minerals; (2) prevents corrosion produced by an acidic liquid phase of the wet steam resulting from acid-overtreatment; and (3) improving the steam injection rate into the formation. It is the principle object of this invention to provide such a method.